In natural mineral oil deposits, mineral oil is present in the cavities of porous reservoir rocks which are sealed toward the surface of the earth by impervious overlying strata. The cavities may be very fine cavities, capillaries, pores or the like. Fine pore necks may have, for example, a diameter of only about 1 μm. As well as mineral oil, including fractions of natural gas, a deposit generally also comprises water with a greater or lesser salt content.
If a mineral oil deposit has a sufficient autogenous pressure, after drilling of the deposit has commenced, mineral oil flows through the well to the surface of its own accord because of the autogenous pressure (primary mineral oil production). Even if a sufficient autogenous pressure is present at first, however, the autogenous pressure of the deposit generally declines relatively rapidly in the course of withdrawal of mineral oil, and so usually only small amounts of the amount of mineral oil present in the deposit can be produced in this manner, according to the deposit type.
Therefore, when primary production declines, a known method is to drill further wells into the mineral oil-bearing formation in addition to the wells which serve for production of the mineral oil, called the production wells. Through these so-called injection wells, water is injected into the deposit in order to maintain the pressure or increase it again. The injection of the water forces the mineral oil through the cavities in the formation, proceeding gradually from the injection well in the direction of the production well. This technique is known as water flooding and is one of the techniques of what is called secondary oil production. In the case of water flooding, however, there is always the risk that the mobile water will not flow homogeneously through the formation and in doing so mobilize oil, but will flow from the injection well to the production well, particularly along paths with a low flow resistance, without mobilizing oil, while there is only little flow, if any, through regions in the formation with high flow resistance. This is discerned from the fact that the proportion of the water which is produced via the production well increases ever further. By means of primary and secondary production, generally not more than about 30% to 35% of the amount of mineral oil present in the deposit can be produced.
A known method is to use techniques for tertiary mineral oil production (also known as “Enhanced Oil Recovery (EOR)”) to enhance the oil yield, if economically viable production is impossible or no longer possible by means of primary or secondary mineral oil production. Tertiary mineral oil production includes processes in which suitable chemicals, such as surfactants and/or polymers, are used as auxiliaries for oil production. An overview of tertiary oil production using chemicals can be found, for example, in the article by D. G. Kessel, Journal of Petroleum Science and Engineering, 2 (1989) 81-101.
One of the techniques of tertiary mineral oil production is called “polymer flooding”. Polymer flooding involves injecting an aqueous solution of a thickening polymer into the mineral oil deposit through the injection wells, the viscosity of the aqueous polymer solution being matched to the viscosity of the mineral oil. The injection of the polymer solution, as in the case of water flooding, forces the mineral oil through said cavities in the formation from the injection well proceeding in the direction of the production well, and the mineral oil is produced through the production well. By virtue of the polymer formulation having about the same viscosity as the mineral oil, the risk that the polymer formation will break through to the production well with no effect is reduced. Thus, the mineral oil is mobilized much more homogeneously than when water, which is mobile, is used, and additional mineral oil can be mobilized in the formation. Details of polymer flooding and polymers suitable for this purpose are disclosed, for example, in “Petroleum, Enhanced Oil Recovery, Kirk-Othmer, Encyclopedia of Chemical Technology, Online Edition, John Wiley & Sons, 2010”.
Use of hydrophobically associating copolymers for polymer flooding is known. “Hydrophobically associating copolymers” are understood by those skilled in the art to mean water-soluble polymers having lateral or terminal hydrophobic groups, for example relatively long alkyl chains. In an aqueous solution, such hydrophobic groups can associate with themselves or with other substances having hydrophobic groups. This results in formation of an associative network which causes (additional) thickening action. Details of the use of hydrophobically associating copolymers for tertiary mineral oil production are described, for example, in the review article by Taylor, K. C. and Nasr-El-Din, H. A. in J. Petr. Sci. Eng. 1998, 19, 265-280.
A further form of tertiary mineral oil production is surfactant flooding for the purpose of producing the oil trapped in the pores by capillary forces, usually combined with polymer flooding for mobility control (homogeneous flow through the deposit).
Viscous and capillary forces act on the mineral oil which is trapped in the pores of the deposit rock toward the end of the secondary production, the ratio of these two forces relative to one another determining the microscopic oil removal. A dimensionless parameter, called the capillary number, is used to describe the action of these forces. It is the ratio of the viscosity forces (velocity×viscosity of the forcing phase) to the capillary forces (interfacial tension between oil and water×wetting of the rock):
      N    c    =                    μ        ⁢                                  ⁢        v            σcosθ        .  
In this formula, μ is the viscosity of the fluid mobilizing the mineral oil, ν is the Darcy velocity (flow per unit area), σ is the interfacial tension between liquid mobilizing mineral oil and mineral oil, and θ is the contact angle between mineral oil and the rock (C. Melrose, C. F. Brandner, J. Canadian Petr. Techn. 58, October-December, 1974). The higher the capillary number, the greater the mobilization of the oil and hence also the degree of oil removal.
It is known that the capillary number toward the end of secondary mineral oil production is in the region of about 10−6 and that it is necessary for the mobilization of additional mineral oil to increase the capillary number to about 10−3 to 10−2.
For this purpose, it is possible to conduct a particular form of the flooding method—what is known as Winsor type III microemulsion flooding. In Winsor type III microemulsion flooding, the injected surfactants are supposed to form a Winsor type III microemulsion with the water phase and oil phase present in the deposit. A Winsor type III microemulsion is not an emulsion with particularly small droplets, but rather a thermodynamically stable, liquid mixture of water, oil and surfactants. The three advantages thereof are that                a very low interfacial tension σ between mineral oil and aqueous phase is thus achieved,        it generally has a very low viscosity and as a result is not trapped in a porous matrix,        it forms with even the smallest energy inputs and can remain stable over an infinitely long period (conventional emulsions, in contrast, require high shear forces which predominantly do not occur in the reservoir, and are merely kinetically stabilized).        
The Winsor type III microemulsion is in equilibrium with excess water and excess oil. Under these conditions of microemulsion formation, the surfactants cover the oil-water interface and lower the interfacial tension σ more preferably to values of <10−2 mN/m (ultra-low interfacial tension). In order to achieve an optimal result, the proportion of the microemulsion in the water-microemulsion-oil system, for a defined amount of surfactant, should naturally be at a maximum, since this allows lower interfacial tensions to be achieved.
In this manner, it is possible to alter the form of the oil droplets (the interfacial tension between oil and water is lowered to such a degree that the smallest interface state is no longer favored and the spherical form is no longer preferred), and they can be forced through the capillary openings by the flooding water.
When all oil-water interfaces are covered with surfactant, in the presence of an excess amount of surfactant, the Winsor type III microemulsion forms. It thus constitutes a reservoir for surfactants which cause a very low interfacial tension between oil phase and water phase. By virtue of the Winsor type III microemulsion having a low viscosity, it also migrates through the porous deposit rock in the flooding process. Emulsions, in contrast, may remain suspended in the porous matrix and block deposits. If the Winsor type III microemulsion meets an oil-water interface as yet uncovered with surfactant, the surfactant from the microemulsion can significantly lower the interfacial tension of this new interface and lead to mobilization of the oil (for example by deformation of the oil droplets).
The oil droplets can subsequently combine to give a continuous oil bank. This has two advantages:
Firstly, as the continuous oil bank advances through new porous rock, the oil droplets present there can coalesce with the bank.
Moreover, the combination of the oil droplets to give an oil bank significantly reduces the oil-water interface and hence surfactant no longer required is released again. Thereafter, the surfactant released, as described above, can mobilize oil droplets remaining in the formation.
Winsor type III microemulsion flooding is consequently an exceptionally efficient process, and requires much less surfactant compared to an emulsion flooding process. In microemulsion flooding, the surfactants are typically optionally injected together with cosolvents and/or basic salts (optionally in the presence of chelating agents). Subsequently, a solution of thickening polymer is injected for mobility control. A further variant is the injection of a mixture of thickening polymer and surfactants, cosolvents and/or basic salts (optionally with chelating agent), and then a solution of thickening polymer for mobility control. These solutions should generally be clear in order to prevent blockages of the reservoir.
The use parameters, for example type, concentration and mixing ratio of the surfactants used relative to one another, are adjusted by the person skilled in the art to the conditions prevailing in a given oil formation (for example temperature and salt content).